Europe gives priority to reducing power plant NOx and SOx emissions

Europe gives priority to reducing power plant NOx and SOx emissions

Cleaning up the environment is a major reason that Europe`s electric generating companies are installing scrubbers, low-NOx burners and AFBC

By Kevin Dodman

European Editor

A recent conference held in Prague, “Energy and Environment: Transitions in East Central Europe,” organized and co-sponsored by the University of North Dakota`s Energy & Environment Research Center in the United States and the Power Research Institute of Prague, Czech Republic, highlighted the scale of the energy production and environmental control challenges facing the emerging economies of the Central European region.

Its purpose was to provide opportunities for the discussion of available energy and environmental technology options, stimulate the formation of business partnerships, and identify key barrier issues hindering the application of technology.

Vice Minister Vladimir Novotny of the Czech Ministry of the Environment commented, “This conference provides an opportunity to receive detailed information on well-established ways of solving energy and environmental problems. It also offers the possibility to consult with experienced experts and to make contacts for additional cooperation.”

The Czech Republic was an appropriate venue for the event, as recent legislation calls for cleanup of power plants there on a massive scale before the end of the century and a wide range of environmental control projects is therefore already underway. Robert Gentile, former Assistant Secretary for Fossil Energy in the US Department of Energy (DOE), said, “The private sector is flourishing in the Czech Republic. Clearly, private sector partnerships are what`s causing this to happen. It`s no longer the government relationship that existed in the past. It`s all strictly in the private sector now.”

Czech Republic

CEZ, the Czech power utility, is the country`s dominant producer of electricity, supplying 80 percent of total demand from an installed capacity of 10,655 MW, of which 7,677 MW is coal fired, 1,760 MW nuclear and 1,218 MW hydropower. CEZ became a public limited company in May 1992 and approximately 70 percent of its shares are owned by the state National Property Fund. Most of the remainder are owned by investment and privatization funds, and 4 percent by private individuals.

It is the largest company in the Czech Republic, with a market capitalization of approximately (US)$3.4 billion. Revenue in 1993 was (US)$1.71 billion, operating income (US)$732 million and net income (US)$328 million.

CEZ has embarked on an ambitious program of environmental control projects in order to comply with the latest Clean Air Act, which requires that fossil fuel power plants should comply with the emission levels shown in Table 1 by the end of 1998. These levels compare closely to those for new power plants in the European Community countries (Figure 1).

An additional requirement of the Clean Air Act is that if the new SO2 limits cannot be met without flue gas desulfurization (FGD), then FGD equipment must be installed. Emissions must then be no more than 15 percent of pre-FGD levels for plants over 300 MWt and 30 percent of pre-FGD levels for plants between 50 MWt and 300 MWt.

CEZ`s strategy for reducing SO2 emissions is divided into 4 main areas:

1. Closure of the oldest coal-fired capacity and replacement with the Temelin nuclear power plant

2. Substitution of natural gas and imported hard coal fordomestic lignite where possible

3. Installation of FGD

4. Retrofitting old plants with fluidized-bed boilers

After 1989, a downturn in the economy led to a fall in electricity demand. However, it bottomed out in 1993 and is now rising again and is expected to return to 1989 levels around the year 2000. Today`s excess capacity, plus the construction of new power plants, gives CEZ the opportunity to close old plants. The first Temelin power plant unit is expected to enter service in 1996-97, with the second following within 18 months. Each unit will have a capacity of 981 MW.

The Czech Republic is dependent on the former Soviet Union for supplies of natural gas, which is only likely to be cost-effective if combined-cycle technology is used. However, the investment cost to install a new combined-cycle plant is considered to be too high compared to the cost of cleaning up existing coal-fired power stations. Converting from lignite to imported hard coal would be the cheapest option, but to avoid installing FGD at large plants, the sulfur content would need to be a maximum of 0.1 g/MJ, and as yet no suitable fuel sources have been found.

Eight plants, with a total capacity of 6,000 MW, are scheduled to have FGD installed. Four projects are currently under construction (Pocerady 1 and 2 and Prunerov 1 and 2) and the tender process has been completed for two more at Tusimice and Ledvice. The planned rate of cleanup of coal-fired units is shown in Figure 2.

A number of other projects are either planned or already underway. These include Tisova, Ledvice, Hodonin and Porici which range in size from 170 MW to 350 MW.

Through the year 2000, out of a total investment expenditure of (US)$4.49 billion, CEZ anticipates spending (US)$1.17 billion on completing the Temelin nuclear plant, (US)$970 million on desulfurization of fossil-fired power stations, (US)$229 million on fluidized-bed replacements for pulverized coal-fired boilers, and (US)$125 million on de-NOx and other environmental investments. The investment breakdown is shown in Figure 3.

These investments form the major part of the company`s total capital requirements of (US)$6.55 billion up to the year 2000. Of this total, it is anticipated that (US)$3.88 billion will come from the company`s revenues, and (US)$2.66 billion from borrowing.

NOx control in the Czech Republic

Planned investments in NOx reduction are low compared to the amount anticipated to be spent for FGD systems. This is because many plants will continue to burn domestic lignite at relatively low combustion temperatures thus limiting the formation of NOx. However, improvements are needed, and a paper presented by EGU Praha1 at the Prague conference outlined some of the work that has been carried out to reduce NOx emissions at some plants by improving fuel preparation, optimizing combustion air distribution, modifying burner configurations, and installing updated control and measurement systems.

At several lignite-fired power plants, Czech specialists have carried out NOx reduction programs without foreign assistance but at the hard-coal-fired plants technology transfer is needed. An example is the project currently underway at the 800-MW hard-coal-fired Detmarovice power plant in northern Moravia, on the border between the Czech Republic and Poland. Here, Finnish power engineering company IVO International is cooperating with EkoEngineering, a Czech environmental engineering specialist, to supply low-NOx burners. These are similar in design to those used at IVO`s own Meri-Pori power plant in western Finland, which is reported to be one of the world`s cleanest and most efficient coal-fired power stations.

Lumir Jendryscik, Detmarovice plant deputy director of production and technology, explained that each of its four 52 meter high boilers produces 650 tons/hr of steam at 540 C and 18.5 MPa. The new burners are being installed on four levels between 12 meters and 18 meters, with secondary air fed in at the 25 meter level. Conversion of the first boiler was completed during 1994 and as we went to press, it was due to start initial testing. The anticipated NOx level is 450 mg/Nm3.

Bidding is currently underway for the FGD system at Detmarovice, with commissioning of the first unit scheduled for 1997. SO2 emissions at the plant are currently in the 1,300 mg/Nm3 to 1,500 mg/Nm3 range. After conversion, the limit will be around 195-225 mg/Nm3, to comply with the Clean Air Act`s 85 percent reduction requirement.


While there is no formal requirement that domestic suppliers should be used, local content is an important consideration because labor costs in the Czech Republic are around a tenth of the level of Western Europe. Many bidders therefore use local sub-suppliers or consortium partners.

The Czech Republic is currently an attractive market for western suppliers because finance seems to be more readily available than in some other areas of Central Europe, where international financiers regard energy prices as too low.

The current average end-user tariffs in the Czech Republic are:

Industrial (US)$0.05/kWh

Commercial (US)$0.07/kWh

Residential (US)$0.03/kWh

Large Czech companies can fund a significant level of new projects themselves but the amount of investment needed over the next few years means that external funding is also needed, so direct foreign investment is now being considered in addition to credit financing.

Much of the work needed to complete the Temelin plant is being financed by a (US)$422 million loan from CitiBank, partly guaranteed by US Exim Bank and OND of Belgium. For other projects, CEZ signed loan contracts without state, bank or property guarantees in 1993 and during 1994 received the rating BBB with positive outlook from Standard and Poor`s.

The Northern Bohemia area of the Czech Republic, which borders Germany and Poland, lies in one of Europe`s most polluted areas, as the fuel most commonly used for factories and power plants there is high sulfur and high ash brown coal. SO2 emissions of up to 4,000 mg/Nm3 are common.

A number of environmental control projects are underway in the region, including an atmospheric fluidized bed boiler bottom retrofit to 10 traveling stoker grate units at the 927 MWt First Northwest Power and Heating Plant at Komor2, near the city of Most.

The plant was one of the first to be privatized when the Czech political and economic system was restructured. In 1991, feasibility studies carried out by Power International of the United States concluded that atmospheric fluidized bed combustion (AFBC) would be the best way to meet the requirements of the Clean Air Act using existing fuel. Details of the process conditions and estimated emissions are shown in Tables 2 and 3.

The plant subsequently contracted Power International to design and engineer the retrofit, which will cost approxiamtely (US)$100 million for all 10 units. Conversion of the first unit, financed from the plant`s own resources, has been completed and it is scheduled to be fully dispatchable in early 1995. The remaining units will be converted in phases, with the final unit coming on line in late 1998.

Each boiler will use the same design of AFBC installation and will be equipped with its own coal and limestone metering systems, ash removal equipment, emissions control, instrumentation and control systems.

The plan area of each grate is 6.5 meters by 10.5 meters, and the existing combustion chambers are approximately 13 meters high. The retrofit involves removing the traveling grates and lower parts of each boiler, then joining the new bottom-supported fluidized-bed combustors to the existing furnace walls using a flexible seal. They will incorporate new forced circulation heat transfer surfaces within the dense bed to maintain bed temperature below 843 C, which will minimize bed material agglomeration and maximize sulfur capture.

Additional pendant superheaters will be added upstream of the existing superheaters to ensure that final superheat temperature is maintained. Following final cleanup in individual fabric filters, the flue gas from all 10 units will exit through a single stack.

The retrofit will result in a 98 percent reduction in particulate emissions, 88 percent less SO2 and a 38 percent reduction in NOx levels compared to the grate-fired configuration.

Lignite firing

Over the border in Germany, lignite is likely to remain an important fuel, as it is readily available in the eastern part of the country. In addition, it can be produced at a cost that is competitive with both imported coal and the subsidized hard coal mined in the Ruhr district further to the west. As a consequence, work is under way to clean up existing lignite-fired capacity and to develop new ways to burn the fuel efficiently.

The J?nschwalde power station near the city of Cottbus, about 20 kilometers from the Polish border, is operated by VEAG and is one of the most modern lignite-fired power plants in the area. Its six 500-MWe units are being fitted with a Noell/KRC two-stage wet scrubbing FGD process. This scrubber is similar to that used at 33 other lignite-fired power plants operated by the utility RWE. The 33 plants have a combined capacity of 9,300 MW.

The system installed at J?nschwalde will meet very tight emission limits, which call for a 95 percent reduction in SO2 concentration from 4,000 mg/Nm3 to 200 mg/Nm3. The conversion, which will cost a total of approximately (US)$1.8 billion, is being carried out by Siemens and is scheduled for completion by July 1996.

RWE Energie is continuing development of the KoBra process, which is an integrated gasification combined-cycle (IGCC) system based on an air-blown fluidized-bed gasifier.

The company estimates that the technology will be commercially viable after the year 2004, and based on current experience, said that half its lignite-fired capacity could be using the KoBra process by the year 2020.

RWE also recently announced that it will build a 900-MW lignite-fired power plant at Frimmersdorf. This plant is scheduled for commissioning before the end of 1999. Initial estimates are that it will have an efficiency of approximately 43 percent.

IGCC and CO2 reduction

In a paper presented at the POWER-GEN Europe `94 conference3, Siemens pointed out that future goals for the reduction of CO2 emissions will require not just a move towards using fuels with lower carbon content in relation to their energy content, but also separation of CO2.

The company said that the IGCC process would enable coal to remain a viable fuel for power generation, even with its relatively high CO2 potential.

However, this would require the addition of components, such as combined H2S/CO2 wash and CO shift reactors. Siemens estimates that in this way, CO2 removal efficiencies in excess of anticipated global requirements could be achieved while maintaining plant efficiency of approximately 40 percent, although this would add 10 percent to the capital cost of the plant compared to a standard IGCC installation.

Siemens claims that power plants based on these concepts could be built immediately, either as new plants or as refit variants for existing IGCC projects, as all the additional components needed have already been proven on an industrial scale. The status of current IGCC development projects is shown in Figure 4.

UK update

In the United Kingdom, a number of emission reduction options have been considered, including the possible use of IGCC. However, the availability of natural gas at a favorable price has led to the adoption of combined-cycle gas turbine (CCGT) technology for new power plants. Two of the most recent to be commissioned were the 900-MW Killingholme plant on the country`s east coast, and the 700-MW Rye House power plant near London, both built by Siemens for PowerGen. The Rye House plant was one of the award winners of Power Engineering and Power Engineering International`s 1994 Project of the Year Awards.

Compared to the 900-MW coal-fired power plant originally planned for the Killingholme site by the Central Electricity Generating Board (which was subsequently privatized to form National Power and PowerGen), a natural gas-fired CCGT power station has immediate environmental advantages, as shown in Figure 5.

FGD is being installed at a number of existing coal-fired power plants in the United Kingdom. The largest is at the National Power`s Drax 4,000-MW power station in Yorkshire. Drax burns coals with a sulfur content of up to 2.8 percent. Six limestone/gypsum FGD units are being built to remove 90 percent of the SO2 in the flue gas, a total of approximately 280,000 tons/yr when fully operational. The first two units entered service in late 1993 and the others will come on line in 1995 and 1996.

For the foreseeable future, CCGT technology is likely to remain the preferred option for new power plants in the United Kingdom, certainly until other technologies are well proven in other countries. In September 1994, the latest large CCGT project was announced, a 750-MW power station on the River Humber. This plant will use the latest ABB GT13E2 gas turbines.

The River Humber plant is scheduled to enter service in early 1997 and will be an independent power project. The four participants are ABB, IVO of Finland, Midlands Electricity, a leading UK regional electricity company, and Tomen Corp., a Japanese trading company.

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1 Optimization of Boiler Technology and Control Aimed at Improving Economic and Environmental Parameters. P. Neuman, V. Stosek, V. Mechura and Z. Masek. EGU Praha

2 Multiple Stoker Fired Retrofit with Fluidized Bed Combustion. G.C. Snow, L.W. Jacobson Power International Inc. Coeur d`Alene, Idaho, USA

3 GUD Power Plant with Integrated Coal Gasification CO Shift and CO2 Washing. Pruschek, Oeljeklaus and Brand, Universitat, Essen; Haupt and Zimmermann, Siemens AG. Presented by Siemens at Power Gen Europe `94, Cologne

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